Diversion acid containing a water-soluble retarding agent and methods of making and using

ABSTRACT

Described herein are aqueous composition(s) containing water; a viscoelastic surfactant; an acid; and a water-soluble acid retarding agent. Further described are methods of making and using such compositions.

RELATED APPLICATION INFORMATION

This application claims the benefit of U.S. Provisional Application Ser. No. 62/214,047 filed Sep. 3, 2015, which is incorporated herein in its entirety.

FIELD

The disclosure relates to diversion acids containing water-soluble acid retarding agents, and to methods of making and using.

BACKGROUND

This section provides background information to facilitate a better understanding of the various aspects of the disclosure. It should be understood that the statements in this section of this document are to be read in this light, and not as admissions of prior art.

The maintenance and stimulation of oil and gas wells with specially designed fluids is critical to the efficient extraction of these resources. Well treatment fluids have many roles: hydraulic fracturing, gravel packing, water flooding and acidizing. Acid treatment is considered the oldest well stimulation technology, having first been applied in 1895. When injected at low rates into carbonate formations, hydrochloric acid (HCl) can form conductive wormholes that extend radially from the well bore. Acids can also be injected into subterranean formations at rates high enough to cause fracturing. In this case, the acid unevenly dissolves the walls of the fracture, so that when the injection is stopped and the fracture closes, conductive channels extending the length of the fracture remain.

HCl is very reactive, and at higher temperatures (>200° F.) and/or low injection rates favor facial dissolution over wormholing in matrix treatments. For this reason, less reactive acid formulations were pursued. One approach is to use organic acids such as formic and acetic acid. Organic acids have higher pKa's than HCl, and will not completely spend in the reservoir. A second approach is to suspend the acid as a water-in-oil emulsion, which restricts aqueous acid contact with the reservoir and thus slows the reaction rate. In recent work, we have developed a method whereby HCl reactivity is attenuated by certain water soluble compounds to create single-phase retarded acid systems.

During an acid treatment, the highest permeability parts of the formation will accept the largest volumes of acid, thus increasing the permeability of these high permeability zones even further. Continued treatment of these same zones does little to stimulate production in other parts of the reservoir. To redirect acid flow to less permeable parts of the reservoir, diversion fluids are often pumped between acid stages. The diversion fluids are designed to enter the most permeable sections of the formation and create a temporary plug. The following acid stage will be sent to another part of the formation, and these stages can iterate to achieve optimal fluid placement.

A variety of materials can serve as diversion agents. Simple compounds such as benzoic acid flakes are used to plug the formation very close to the wellbore, and then dissolve into the natural hydrocarbons as the well is put into production. Oil-soluble resins also work in this manner. Other fluids, often containing polymer or surfactants, are designed to viscosify in the formation, setting a thick plug that will break after the treatment is complete.

SUMMARY

This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.

In a first aspect of the disclosure, aqueous composition(s) are provided including: water; a viscoelastic surfactant; an acid; and a water-soluble acid retarding agent.

In another aspect of the disclosure, methods are provided including a) providing an aqueous composition including: water; a viscoelastic surfactant; an acid; and a water-soluble acid retarding agent; and b) treating a formation fluidly coupled to a wellbore with an oilfield treatment fluid comprising the aqueous composition.

BRIEF DESCRIPTION OF THE DRAWINGS

Certain embodiments of the disclosure will hereafter be described with reference to the accompanying drawings, wherein like reference numerals denote like elements. It should be understood, however, that the accompanying figures illustrate the various implementations described herein and are not meant to limit the scope of various technologies described herein, and:

FIG. 1 depicts an example of equipment used to treat a wellbore and/or a formation fluidly coupled to the wellbore according to some embodiments of the disclosure;

FIG. 2 shows pore volumes to break through versus interstitial velocity curves for aqueous acid solutions based upon tests performed at 70° F., according to the disclosure;

FIG. 3 shows pore volumes to break through versus interstitial velocity curves for aqueous acid solutions based upon tests performed at 200° F., according to the disclosure;

FIGS. 4A-4E depict face dissolution of core samples evaluated in accordance with the disclosure; and,

FIG. 5 shows calcium generation concentration versus time curves for some aqueous acid solutions evaluated, according to the disclosure.

FIG. 6 shows viscosity versus shear rate for fresh VDA's containing viscoelastic surfactant and HCl with and without MgCl₂.

FIG. 7 shows viscosity versus shear rate for spent VDA's containing viscoelastic surfactant and HCl with and without MgCl₂.

FIG. 8 shows pore volume to breakthrough (PVBT) versus flow rate for a VDA containing viscoelastic surfactant and HCl with and without MgCl₂.

FIG. 9 depicts wormhole patterns in the limestone cores after the treatment with VDA's containing viscoelastic surfactant and HCl with and without MgCl₂, and at the same flow rate 0.2 ml/min.

FIG. 10 shows normalized pressure versus pore volume (PV) for a VDA containing viscoelastic surfactant and HCl with and without MgCl₂ at flow rate 6 ml/min.

FIG. 11 shows a computer simulated graph of MD (measured depth) versus wormhole radius (at 100 md (millidarcy)/1 md permeability contrast) with 0.5 bbl/min total injection rate of a VDA containing viscoelastic surfactant and HCl with and without MgCl₂.

FIG. 12 shows a computer simulated graph of rate per zone versus time (at 100 md/1 md permeability contrast) with 0.5 bbl/min total injection rate of a VDA containing viscoelastic surfactant and HCl with and without MgCl₂.

FIG. 13 shows a computer simulated graph of MD (length of the wellbore) versus wormhole radius (at 100 md/1 md permeability contrast) with 1 bbl/min total injection rate of a VDA containing viscoelastic surfactant and HCl with and without MgCl₂.

FIG. 14 shows a computer simulated graph of rate per zone versus time (at 100 md/1 md permeability contrast) with 1 bbl/min total injection rate of a VDA containing viscoelastic surfactant and HCl with and without MgCl₂.

FIG. 15 shows a computer simulated graph of MD (length of the wellbore) versus wormhole radius (at 100 md/1 md permeability contrast) with 5 bbl/min total injection rate of a VDA containing viscoelastic surfactant and HCl with and without MgCl₂.

FIG. 16 shows a computer simulated graph of rate per zone versus time (at 100 md/1 md permeability contrast) with 5 bbl/min total injection rate of a VDA containing viscoelastic surfactant and HCl with and without MgCl₂.

FIG. 17 shows a computer simulated graph of MD (length of the wellbore) versus wormhole radius (at 100 md/1 md permeability contrast) with 10 bbl/min total injection rate of a VDA containing viscoelastic surfactant and HCl with and without MgCl₂.

FIG. 18 shows a computer simulated graph of rate per zone versus time (at 100 md/1 md permeability contrast) with 10 bbl/min total injection rate of a VDA containing viscoelastic surfactant and HCl with and without MgCl₂.

FIG. 19 shows a computer simulated graph of MD (length of the wellbore) versus wormhole radius (at 100 md/10 md permeability contrast) with 0.5 bbl/min total injection rate of a VDA containing viscoelastic surfactant and HCl with and without MgCl₂.

FIG. 20 shows a computer simulated graph of rate per zone versus time (at 100 md (millidarcy)/10 md permeability contrast) with 0.5 bbl/min total injection rate of a VDA containing viscoelastic surfactant and HCl with and without MgCl₂.

FIG. 21 shows a computer simulated graph of MD (length of the wellbore) versus wormhole radius (at 100 md/10 md permeability contrast) with 1 bbl/min total injection rate of a VDA containing viscoelastic surfactant and HCl with and without MgCl₂.

FIG. 22 shows a computer simulated graph of rate per zone versus time (at 100 md (millidarcy)/10 md permeability contrast) with 1 bbl/min total injection rate of a VDA containing viscoelastic surfactant and HCl with and without MgCl₂.

FIG. 23 shows a computer simulated graph of MD (length of the wellbore) versus wormhole radius (at 100 md/10 md permeability contrast) with 5 bbl/min total injection rate of a VDA containing viscoelastic surfactant and HCl with and without MgCl₂.

FIG. 24 shows a computer simulated graph of rate per zone versus time (at 100 md (millidarcy)/10 md permeability contrast) with 5 bbl/min total injection rate of a VDA containing viscoelastic surfactant and HCl with and without MgCl₂.

FIG. 25 shows a computer simulated graph of MD (length of the wellbore) versus wormhole radius (at 100 md/10 md permeability contrast) with 10 bbl/min total injection rate of a VDA containing viscoelastic surfactant and HCl with and without MgCl₂.

FIG. 26 shows a computer simulated graph of rate per zone versus time (at 100 md (millidarcy)/10 md permeability contrast) with 10 bbl/min total injection rate of a VDA containing viscoelastic surfactant and HCl with and without MgCl₂.

FIG. 27 shows a computer simulated graph of MD (length of the wellbore) versus wormhole radius (at 100 md/20 md permeability contrast) with 0.5 bbl/min total injection rate of a VDA containing viscoelastic surfactant and HCl with and without MgCl₂.

FIG. 28 shows a computer simulated graph of rate per zone versus time (at 100 md (millidarcy)/20 md permeability contrast) with 0.5 bbl/min total injection rate of a VDA containing viscoelastic surfactant and HCl with and without MgCl₂.

FIG. 29 shows a computer simulated graph of MD (length of the wellbore) versus wormhole radius (at 100 md/20 md permeability contrast) with 1 bbl/min total injection rate of a VDA containing viscoelastic surfactant and HCl with and without MgCl₂.

FIG. 30 shows a computer simulated graph of rate per zone versus time (at 100 md (millidarcy)/20 md permeability contrast) with 1 bbl/min total injection rate of a VDA containing viscoelastic surfactant and HCl with and without MgCl₂.

FIG. 31 shows a computer simulated graph of MD (length of the wellbore) versus wormhole radius (at 100 md/20 md permeability contrast) with 5 bbl/min total injection rate of a VDA containing viscoelastic surfactant and HCl with and without MgCl₂.

FIG. 32 shows a computer simulated graph of rate per zone versus time (at 100 md (millidarcy)/20 md permeability contrast) with 5 bbl/min total injection rate of a VDA containing viscoelastic surfactant and HCl with and without MgCl₂.

FIG. 33 shows a computer simulated graph of MD (length of the wellbore) versus wormhole radius (at 100 md/20 md permeability contrast) with 10 bbl/min total injection rate of a VDA containing viscoelastic surfactant and HCl with and without MgCl₂.

FIG. 34 shows a computer simulated graph of rate per zone versus time (at 100 md (millidarcy)/20 md permeability contrast) with 10 bbl/min total injection rate of a VDA containing viscoelastic surfactant and HCl with and without MgCl₂.

FIG. 35 shows a computer simulated graph of MD (length of the wellbore) versus wormhole radius (at 100 md/50 md permeability contrast) with 0.5 bbl/min total injection rate of a VDA containing viscoelastic surfactant and HCl with and without MgCl₂.

FIG. 36 shows a computer simulated graph of rate per zone versus time (at 100 md (millidarcy)/50 md permeability contrast) with 0.5 bbl/min total injection rate of a VDA containing viscoelastic surfactant and HCl with and without MgCl₂.

FIG. 37 shows a computer simulated graph of MD (length of the wellbore) versus wormhole radius (at 100 md/50 md permeability contrast) with 1 bbl/min total injection rate of a VDA containing viscoelastic surfactant and HCl with and without MgCl₂.

FIG. 38 shows a computer simulated graph of rate per zone versus time (at 100 md (millidarcy)/50 md permeability contrast) with 1 bbl/min total injection rate of a VDA containing viscoelastic surfactant and HCl with and without MgCl₂.

FIG. 39 shows a computer simulated graph of MD (length of the wellbore) versus wormhole radius (at 100 md/50 md permeability contrast) with 5 bbl/min total injection rate of a VDA containing viscoelastic surfactant and HCl with and without MgCl₂.

FIG. 40 shows a computer simulated graph of rate per zone versus time (at 100 md (millidarcy)/50 md permeability contrast) with 5 bbl/min total injection rate of a VDA containing viscoelastic surfactant and HCl with and without MgCl₂.

FIG. 41 shows a computer simulated graph of MD (length of the wellbore) versus wormhole radius (at 100 md/50 md permeability contrast) with 10 bbl/min total injection rate of a VDA containing viscoelastic surfactant and HCl with and without MgCl₂.

FIG. 42 shows a computer simulated graph of rate per zone versus time (at 100 md (millidarcy)/50 md permeability contrast) with 10 bbl/min total injection rate of a VDA containing viscoelastic surfactant and HCl with and without MgCl₂.

DETAILED DESCRIPTION

The following description of the variations is merely illustrative in nature and is in no way intended to limit the scope of the disclosure, its application, or uses. The description and examples are presented herein solely for the purpose of illustrating the various embodiments of the disclosure and should not be construed as a limitation to the scope and applicability of the disclosure. While the compositions of the present disclosure are described herein as comprising certain materials, it should be understood that the composition could optionally comprise two or more chemically different materials. In addition, the composition can also comprise some components other than the ones already cited. In the summary of the disclosure and this detailed description, each numerical value should be read once as modified by the term “about” (unless already expressly so modified), and then read again as not so modified unless otherwise indicated in context. Also, in the summary of the disclosure and this detailed description, it should be understood that a concentration or amount range listed or described as being useful, suitable, or the like, is intended that any and every concentration or amount within the range, including the end points, is to be considered as having been stated. For example, “a range of from 1 to 10” is to be read as indicating each and every possible number along the continuum between about 1 and about 10. Thus, even if specific data points within the range, or even no data points within the range, are explicitly identified or refer to only a few specific, it is to be understood that inventors appreciate and understand that any and all data points within the range are to be considered to have been specified, and that inventors had possession of the entire range and all points within the range.

Unless expressly stated to the contrary, “or” refers to an inclusive or and not to an exclusive or. For example, a condition A or B is satisfied by anyone of the following: A is true (or present) and B is false (or not present), A is false (or not present) and B is true (or present), and both A and B are true (or present).

In addition, use of the “a” or “an” are employed to describe elements and components of the embodiments herein. This is done merely for convenience and to give a general sense of concepts according to the disclosure. This description should be read to include one or at least one and the singular also includes the plural unless otherwise stated.

The terminology and phraseology used herein is for descriptive purposes and should not be construed as limiting in scope. Language such as “including,” “comprising,” “having,” “containing,” or “involving,” and variations thereof, is intended to be broad and encompass the subject matter listed thereafter, equivalents, and additional subject matter not recited.

Also, as used herein any references to “one embodiment” or “an embodiment” means that a particular element, feature, structure, or characteristic described in connection with the embodiment is included in at least one embodiment. The appearances of the phrase “in one embodiment” in various places in the specification are not necessarily referring to the same embodiment.

The terms “formation” or “subterranean formation” as utilized herein should be understood broadly, and are used interchangeably. A formation includes any underground fluidly porous formation, and can include without limitation any oil, gas, condensate, mixed hydrocarbons, paraffin, kerogen, water, and/or CO₂ accepting or providing formations. A formation can be fluidly coupled to a wellbore, which may be an injector well, a producer well, and/or a fluid storage well. The wellbore may penetrate the formation vertically, horizontally, in a deviated orientation, or combinations of these. The formation may include any geology, including at least a sandstone, limestone, dolomite, shale, tar sand, and/or unconsolidated formation. The wellbore may be an individual wellbore and/or a part of a set of wellbores directionally deviated from a number of close proximity surface wellbores (e.g. off a pad or rig) or single initiating wellbore that divides into multiple wellbores below the surface.

The term “oilfield treatment fluid” as utilized herein should be understood broadly. In certain embodiments, an oilfield treatment fluid includes any fluid having utility in an oilfield type application, including a gas, oil, geothermal, or injector well. In certain embodiments, an oilfield treatment fluid includes any fluid having utility in any formation or wellbore described herein. In certain embodiments, an oilfield treatment fluid includes a matrix acidizing fluid, a wellbore cleanup fluid, a pickling fluid, a near wellbore damage cleanup fluid, a surfactant treatment fluid, an unviscosified fracture fluid (e.g. slick water fracture fluid), and/or any other fluid consistent with the fluids otherwise described herein. An oilfield treatment fluid may include any type of additive known in the art, which are not listed herein for purposes of clarity of the present description, but which may include at least friction reducers, inhibitors, surfactants and/or wetting agents, fluid diverting agents, particulates, acid retarders (except where otherwise provided herein), organic acids, chelating agents, energizing agents (e.g. CO₂ or N₂), gas generating agents, solvents, emulsifying agents, flowback control agents, resins, breakers, and/or non-polysaccharide based viscosifying agents.

The term “high pressure pump” as utilized herein should be understood broadly. In certain embodiments, a high pressure pump includes a positive displacement pump that provides an oilfield relevant pumping rate—for example at least 0.5 barrels per minute (bpm), although the specific example is not limiting. A high pressure pump includes a pump capable of pumping fluids at an oilfield relevant pressure, including at least 500 psi, at least 1,000 psi, at least 2,000 psi, at least 5,000 psi, at least 10,000 psi, up to 15,000 psi, and/or at even greater pressures. Pumps suitable for oilfield cementing, matrix acidizing, and/or hydraulic fracturing treatments are available as high pressure pumps, although other pumps may be utilized.

The term “treatment concentration” as utilized herein should be understood broadly. A treatment concentration in the context of an HCl concentration is a final concentration of the fluid before the fluid is positioned in the wellbore and/or the formation for the treatment, and can be any concentration necessary to provide sufficient acidic function. The treatment concentration may be the mix concentration available from the HCl containing fluid at the wellsite or other location where the fluid is provided from. The treatment concentration may be modified by dilution before the treating and/or during the treating. Additionally, the treatment concentration may be modified by the provision of additives to the fluid. In certain embodiments, a treatment concentration is determined upstream of additives delivery (e.g. at a blender, hopper, or mixing tub) and the concentration change from the addition of the additives is ignored. In certain embodiments, the treatment concentration is a liquid phase or acid phase concentration of a portion of the final fluid—for example when the fluid is an energized or emulsified fluid.

Aqueous compositions described below and useful in accordance with the disclosure exhibit a retarded acid reactivity that facilitates greater depth of fracture and/or matrix acidizing. The aqueous composition can comprise, consist essentially of, or consist of: water; a viscoelastic surfactant; an acid; and a water-soluble acid retarding agent. The acid can be selected from the group consisting of hydrochloric acid (NCl), nitric acid, phosphoric acid, sulfuric acid, hydrofluoric acid, hydrobromic acid, perchloric acid, hydrogen iodide, alkanesulfonic acids, arylsulfonic acids, acetic acid, formic acid, alkyl carboxylic acids, acrylic acid, lactic acid, glycolic acid, malonic acid, fumaric acid, citric acid, tartaric acid, or their derivatives, and mixtures thereof. Generally, an acid is transported to a wellsite. According to some embodiments, the acid is present in the aqueous compositions in an amount up to about 36 wt %, or from about 7.5 to about 36 wt %, or from about 7.5 to about 28 wt %, or from about 7.5 to about 20 wt %, based on the total weight of the composition. In some other embodiments, acid is present in the aqueous compositions in an amount of at least about 37 wt %.

In some embodiments, an acid that has shown particular utility in the aqueous composition according to the disclosure is hydrochloric acid. In some other embodiments, the aqueous composition may include an amount of hydrofluoric acid (HF). HF exhibits distinct reactions from HCl, and is useful in certain applications to enhance the activity of the resulting aqueous solution. For example, HF is utilized in the cleanup of sandstone formations where HCl alone is not effective for removing certain types of formation damage. It is believed that the present aqueous solution will have effects with HF similarly to the observed effects with HCl. Accordingly, solutions can be formulated with a total acid amount that is much higher than presently attainable formulations. In yet another embodiment, the HF is present in the aqueous composition in an amount of at least 0.25% by weight. The HF may be present in addition to the amount of HCl, and/or as a substitution for an amount of the HCl.

Another component of the aqueous compositions useful according to this disclosure are water-soluble acid retarding agents (RA), which have utility in retarding the rate at which the acid solution reacts with carbonate-mineral, or other surfaces inside the formation. Thus, a water-soluble acid retarding agent may slow the reactivity of the acid towards the carbonate-mineral surfaces, without compromising its acid capacity. Such retardation is useful in the context of stimulating or improving production from subterranean formations that contain hydrocarbons, steam, geothermal brines and other valuable materials as known in the art. Slowing the rate of reaction may allow deeper penetration of the acid into the subterranean formations than regular acid, thereby increasing the formation permeability and productivity. Water-soluble acid retarding agents, as used herein, includes any material that reduces acid activity through a mechanism other than mere dilution. The water-soluble acid retarding agent can comprise a component selected from the group consisting of a salt, urea or one if its derivatives, an alpha-amino acid, a beta-amino acid, a gamma-amino acid, an alcohol with one to five carbons, a surfactant having a structure in accordance with Formula I or Formula II below, and combinations thereof.

-   -   in which R₁ is a hydrocarbyl group that may be branched or         straight chained, aromatic, aliphatic or olefinic and contains         from about 1 to about 26 carbon atoms and may include an amine;         R₂ is hydrogen or an alkyl group having from 1 to about 4 carbon         atoms; R₃ is a hydrocarbyl group having from 1 to about 5 carbon         atoms; and Y is an electron withdrawing group. As an example of         this embodiment, the zwitterionic surfactant has the betaine         structure:

-   -   in which R is a hydrocarbyl group that may be branched or         straight chained, aromatic, aliphatic or olefinic and has from         about 1 to about 26 carbon atoms and may contain an amine;         n=about 2 to about 4; and p=1 to about 5.

The salt can comprise: i) a cation selected from the group consisting of lithium, sodium, potassium, rubidium, cesium, beryllium, magnesium, calcium, strontium, barium, scandium, yttrium, titanium, zirconium, hafnium, vanadium, niobium, tantalum, chromium, molybdenum, tungsten, manganese, technetium, rhenium, iron, ruthenium, osmium, cobalt, rhodium, iridium, nickel, palladium, platinum, copper, silver, gold, zinc, cadmium, mercury, boron, aluminum, gallium, indium, thallium, tin, ammonium, alkylammonium, dialkylammonium, trialkylammonium and tetraalkylammonium, and combinations thereof; and ii) an anion selected from the group consisting of fluoride, chloride, bromide, iodide, sulfate, bisulfate, sulfite, bisulfite nitrate, alkanesulfonates, arylsulfonates, acetate, formate, and combinations thereof. According to the present embodiments, the retarding agent is added to the aqueous composition in an amount up to its solubility limit in the aqueous composition. According to some embodiments, the water-soluble acid retarding agent is present in the aqueous composition(s) in an amount of up to about 40 wt %, or from about 1 to about 40 wt %, or from about 5 to about 35 wt %, or from about 5 to about 20 wt %, based on the total weight of the aqueous composition.

In some embodiments, such as in the presence of urea, the aqueous composition may include HCl as the acid in a weight fraction exceeding 37%. The retarding agent present in some aqueous compositions useful in accordance with the disclosure allows the HCl fraction to exceed the 37% normally understood to be the limit of HCl solubility at atmospheric pressure. Such retarding agents include at least one salt compound and urea, or urea derivative. Above 37%, normally, the evolution of HCl gas from the solution prevents the HCl fraction from getting any higher. In one or more embodiments, the HCl weight fraction of the aqueous solution may be as high as 45.7 wt %.

Without being bound by any particular theory, inventors envisage mechanisms that inhibit acid activity. The first involves the disruption of the hydrogen-bonded network of water. In the Grotthuss proton-hopping mechanism, protons move in water not through Brownian motion, but rather charge transport through shifting hydrogen bonds. Solutes are known to disrupt the Grotthuss mechanism by interacting with water themselves, rather than allowing protons to associate freely. This slows the proton transport to the wormhole wall during a matrix acidizing treatment. The introduction of salt solutes also has a similar second effect by simply replacing water. The lack of water molecules crowds the fluid and limits the diffusion of protons. The amount of RA present in the composition can be any concentration necessary to provide sufficient acid retardation function.

A second mechanism involves the dissociation of acids in solution. As mentioned, organic acids have higher pK_(a)'s than HCl, making the protons from these acids less available for reaction. In some aspects of the disclosure, compounds that lower the polarizability (as indicated by the dielectric constant) of water are used, which therefore decrease the proton dissociation of acids. It is believed that aqueous solutes can modify the activity of acids in water in one or both of these mechanisms.

A parameter that quantifies the retardation of the acid is the retardation factor. As described herein, the retardation factor indicates the ratio of apparent surface reaction rates. According to the present embodiments, the retardation factor of the aqueous composition is higher or equal to a retardation factor of a second solution of acid of a same concentration as the acid comprised in the aqueous composition without the retarding agent. For example, in various embodiments, the aqueous composition may exhibit an acid retardation factor higher than or equal to about 3, at least about 5, or at least about 11 at about 70° F. At about 200° F., the composition may exhibit an acid retardation factor higher than or equal to about 3, higher than or equal to about 5, or even higher than or equal to about 7.

Water is present in the aqueous composition in an amount sufficient to dissolve the acid and the retarding agent. According to embodiments according to the disclosure, the water concentration included in the aqueous composition may be greater than 0 wt % and lower or equal to 80 wt %. In various embodiments, the water concentration may be lower than 60 wt %, or lower than 40 wt % or lower than 20 wt %, and equal to or higher than 8 wt %, or equal to or higher than 10 wt %. In yet other embodiments, the water concentration may even be lower than 8 wt %.

According to some embodiments, an amount of water is mixed with a retarding agent, where the amount of water is present in an amount between 0.3 and 5 times the mass of the RA, where any lower limit can be 0.35, 0.4, or 0.45 and any upper limit can be 1.0, 1.2, 1.25, where any lower limit can be combined with any upper limit. The procedure further includes dissolving an amount of acid into the combined amount of water and RA. The acid, such as HCl, may be added by any method, such as bubbling HCl gas through the solution. The dissolving of the HCl may occur after dissolving of the RA, simultaneous with the dissolving of the RA, or at least partially before the dissolving of the RA. The amount of HCl gas is in a molar ratio of between 4.0 and 0.5 times the amount of the RA. In yet another embodiment, the procedure includes dissolution of at least a portion of the RA in the water during the dissolution of the HCl in the combined water and RA. Example operations include beginning the dissolution of the HCl and adding the RA as a solid or a solution, providing some of the RA in solution with the water and some of the RA as a solid, and/or providing the RA as a solid in the water and dissolving the HCl into the water while dissolving the RA.

Viscoelastic surfactants (VES) create aqueous gels that are employed as oil well treatments for hydraulic fracturing, sand migration control and diversion. US Pat. No. 7,237,608, Fu et al., SELF DIVERTING MATRIX ACID filed in the U.S. Patent Office on Oct. 20, 2004, granted Jul. 3, 2007 is incorporated herein by reference in its entirety, and discloses viscoelastic surfactants, among other things, which are useful for the aqueous composition(s) disclosed herein. The viscoelastic surfactant can comprise a zwitterionic surfactant having a structure in accordance with Formula III or Formula IV below.

in which R₁ is a hydrocarbyl group that may be branched or straight chained, aromatic, aliphatic, or olefinic and contains from about 17 to about 26 carbon atoms and may include an amine; R₂ is hydrogen or an alkyl group having from 1 to about 4 carbon atoms; R₃ is a hydrocarbyl group having from 1 to about 5 carbon atoms; and Y is an electron withdrawing group. As an example of this embodiment, the zwitterionic surfactant has the betaine structure:

in which R is a hydrocarbyl group that may be branched or straight chained, aromatic, aliphatic or olefinic and has from about 17 to about 26 carbon atoms and may contain an amine; n=about 2 to about 4; and p=1 to about 5.

The viscoelastic surfactant can be erucic amidopropyl dimethyl betaine. According to some embodiments, the viscoelastic surfactant is present in the aqueous composition(s) in an amount of up to about 6% v/v or from about 0.02 to about 6% v/v, or from about 0.04 to about 4% v/v, or from about 0.2 to about 3% v/v, based on the total volume of the aqueous composition.

The aqueous composition can be in the form of a gel. The aqueous composition can have a lower viscosity at a pH below about 0 as compared to a viscosity of an equivalent aqueous composition which does not contain the water-soluble acid retarding agent. The aqueous composition can have a viscosity, at temperatures between about 70° F. to about 200° F. and a pH above about 3, which is higher than the viscosity of an equivalent aqueous composition which does not contain the water-soluble acid retarding agent.

Further, it is also within the scope of the present disclosure that the aqueous compositions may be combined with one or more other additives known to those of skill in the art, such as, but not limited to, other diverting agents, such as, but not limited to, acrylamide polymers, fibers, such as polylactic acid, nylon or cellulose, or particulates, such as polylactic acid particulates, sodium chloride particulates or benzoic acid flakes, corrosion inhibitors, scale inhibitors, demulsifiers, foaming agents, hydrogen sulfide scavengers, reducing agents and/or chelants, and the like. For example, non-surface active substituted ammonium containing amino acid derivatives may be used as environmentally friendly corrosion inhibitors that effectively protect various tools employed in oilfield operations by surface treating these tools.

The corrosion inhibitor is typically provided in liquid form and is mixed with the other components of the treatment fluid at the surface and then introduced into the formation. The corrosion inhibitor system is present in the treatment fluid in an amount of from about 0.2% to about 3% by total weight of the treatment fluid. The corrosion inhibitor used with the fluids of the present disclosure includes an alkyl, alkenyl, alycyclic or aromatic substituted aliphatic ketone, which includes alkenyl phenones, or an aliphatic or aromatic aldehyde, which includes alpha, or beta-unsaturated aldehydes, or a combination of these. Alkyl, alycyclic or aromatic phenone and aromatic aldehyde compounds may also be used in certain applications. Other unsaturated ketones or unsaturated aldehydes may also be used. Alkynol phenone, aromatic and acetylenic alcohols and quaternary ammonia compounds, and mixtures of these may be used, as well. These may be dispersed in a suitable solvent, such as an alcohol, and may further include a dispersing agent and other additives.

Chelating agents are materials that are employed, among other uses, to control undesirable reactions of metal ions. In oilfield chemical treatments, chelating agents are frequently added to matrix stimulation acids to prevent precipitation of solids (metal control) as the acids spend on the formation being treated. These precipitates include iron hydroxide and iron sulfide. In addition, chelating agents are used as components in many scale removal/prevention formulations. Two different types of chelating agents may be used: polycarboxylic acids (including aminocarboxylic acids and polyaminopolycarboxylic acids) and phosphonates. The non-surface active substituted ammonium containing aminoacid derivatives may act as chelating agents when present in the treatment fluid in amount of from about 0.05% to about 10% or from about 1 wt % to about 5 wt %, based upon total weight percent of the treatment fluid.

Some embodiments according to present disclosure are methods for treating a formation penetrated by a wellbore. The methods involve providing an oilfield treatment fluid including the aqueous composition as described herein to a high pressure pump and operating the high pressure pump to treat at least one of a wellbore and the formation fluidly coupled to the wellbore. In an embodiment, the aqueous composition is prepared by mixing the acid, the water-soluble acid retarding agent, the viscoelastic surfactant and water present in an amount sufficient to dissolve the other components. The operation of the pump may include at least one of (i) injecting the treatment fluid into the formation at matrix rates; (ii) injecting the treatment fluid into the formation at a pressure equal to a pressure that fractures the formation; and (iii) contacting at least one of the wellbore and the formation with the oilfield treatment fluid.

Referring now to FIG. 1, a system 100 used to treat a wellbore 106 and/or a formation 108 fluidly coupled to the wellbore 106 is depicted. The formation 108 may be any type of formation with a bottom hole temperature up to about 204° C. (400° F.). In various embodiments the temperature is at least 38° C. (100° F.). The temperature may also range from about 38° C. to about 204° C. The wellbore 106 is depicted as a vertical, cased and cemented wellbore 106, having perforations providing fluid communication between the formation 108 and the interior of the wellbore 106. However, the particular features of the wellbore 106 are not limiting, and the example provides an example context 100 for a procedure.

The system 100 includes a high-pressure pump 104 having a source of the aqueous composition 102, as described herein. The high pressure pump 104 is fluidly coupled to the wellbore 106, through high pressure lines 120 in the example. The example system 100 includes tubing 126 in the wellbore 106. The tubing 126 is optional and non-limiting. In various embodiments, the tubing 106 may be omitted, a coiled tubing unit (not shown) may be present, and/or the high pressure pump 104 may be fluidly coupled to the casing or annulus 128. The tubing or casing may be made of steel.

Certain additives (not shown) may be added to the aqueous composition 102 to provide an oilfield treatment fluid. Additives may be added at a blender (not shown), at a mixing tub of the high pressure pump 104, and/or by any other method. In one or more embodiments, a second fluid 110 may be a diluting fluid, and the aqueous composition 102 combined with some amount of the second fluid 110 may make up the oilfield treatment fluid. The diluting fluid may contain no acid, and/or acid at a lower concentration than the aqueous composition 102. The second fluid 110 may additionally include any other materials to be added to the oilfield treatment fluid, including additional amounts of an RA. In certain embodiments, an additional RA solution 112 is present and may be added to the aqueous composition 102 during a portion when the aqueous composition 102 is being utilized. The additional RA solution 112 may include the same or a different RA from the aqueous composition 102, and/or may include RA at a distinct concentration from the aqueous composition.

The high pressure pump 104 can treat the wellbore 106 and/or the formation 108, for example by positioning fluid therein, by injecting the fluid into the wellbore 106, and/or by injecting the fluid into the formation 108. Example and non-limiting operations include any oilfield treatment without limitation. Potential fluid flows include flowing from the high-pressure pump 104 into the tubing 126, into the formation 108, and/or into the annulus 128. The fluid may be recirculated out of the well before entering the formation 108, for example utilizing a back side pump 114. Referring still to FIG. 1, the annulus 128 is shown in fluid communication with the tubing 126. In various embodiments, the annulus 128 and the tubing 126 may be isolated (e.g. with a packer). Another example fluid flow includes flowing the oilfield treatment fluid into the formation at a matrix rate (e.g. a rate at which the formation is able to accept fluid flow through normal porous flow), and/or at a rate that produces a pressure exceeding a hydraulic fracturing pressure. The fluid flow into the formation may be either flowed back out of the formation, and/or flushed away from the near wellbore area with a follow up fluid. Fluid flowed to the formation may be flowed to a pit or containment (not shown), back into a fluid tank, prepared for treatment, and/or managed in any other manner known in the art. Acid remaining in the returning fluid may be recovered or neutralized.

Another example fluid flow includes the aqueous composition 102 including the acid, RA and viscoelastic surfactant. The example fluid flow includes a second aqueous solution 116 including acid and optionally a RA. The fluid flow includes, sequentially, a first high pressure pump 104 and a second high pressure pump 118 treating the formation 108. As seen in FIG. 1, the second high-pressure pump 118 is fluidly coupled to the tubing 126 through a second high pressure line 122. The fluid delivery arrangement is optional and non-limiting. In one embodiment, a single pump may deliver both the aqueous solution 102 and the second aqueous solution 116. In yet another example, either the first aqueous solution 102 or the second aqueous solution 116 may be delivered first, and one or more of the solutions 102, 116 may be delivered in multiple and alternating stages such that the aqueous composition 102 including the acid, RA and viscoelastic surfactant enters the most permeable section(s) of the formation to create a temporary plug, allowing a subsequent stage of the second aqueous solution 116 including acid and optionally a RA to flow to and penetrate less permeable sections of the formation. The method can also potentially include some stages where the solutions 102, 116 are mixed.

The following examples are presented to further illustrate the preparation and properties of the wellbore fluids of the present disclosure and should not be construed to limit the scope of the disclosure, unless otherwise expressly indicated in the appended claims.

EXAMPLES Example 1

Various formulations were prepared using different retarding agents and HCl as the acid. A series of tests were conducted to evaluate these formulations. To fully assess the properties of the prepared formulations, the tests were conducted in an autoclave under up to 3000 psi hydrostatic pressure, with the thermal energy transmitted through a silicone oil bath. To determine the retardation factor (RF) of certain additives, formation response tests were conducted with different acid formulations. In the experiments, Indiana limestone cores, which were 1 inch in diameter by 6 inches in length, were held at ˜2800 psi confining pressure to ensure that no fluids channeled around the sides, and were heated to desired temperature. The acid fluids were flowed through the core, with a ˜1200 psi back pressure, which were conditions provided so the acid will preferentially form wormholes. When the wormhole extended the entire length of the core, the pressure drops across the core approached zero, which was indicative that the fluid was no longer flowing through porous medium, but rather what approximated a tortuous pipe.

The number of pore volumes of fluid required to create the wormholes was a function of the acid injection velocity (u_(i), FIGS. 2 and 3). The optimal injection velocity (u_(i-opt)) is that which requires the lowest number of pore volumes for the wormhole to break through the core. Using this approach, pore volume to break through (PVBT) curves versus interstitial velocity curves were generated and the u_(i-opt) and RF calculated for each acid formulation (Table 1) at 70° F. (FIGS. 2) and 200 ° F. (FIG. 3).

TABLE 1 Retardation Factors of Acid Formulations Estimated Retarding Agent retardation Temperature Retarding Agent concentration factor Entry (° F.) Additive (% by weight) (RF) 1 70 none — — 2 urea 18.5 3.3 3 N,N′-dimethyl 27 5.8 urea (DMU) 4 MgCl₂ 19 10.9  5 200 none — — 6 urea 18.5 1.3 7 MgCl₂ 19 3.1

The estimated retardation factor was calculated according to the following equation:

${RF}_{x} \sim \left( \frac{u_{{i - {opt}},{HCl}}}{u_{{i - {opt}},x}} \right)^{2}$

All aqueous fluids evaluated contained hydrochloric acid (15% weight/volume) and a corrosion inhibitor (0.6% by volume). The results demonstrate that compounds which disrupt the hydrogen bonding network of water and its dielectric constant are able to retard the activity of acid in subterranean formations. In particular, magnesium chloride (MgCl₂) used as a retarding agent showed significant retardation at similar or lower concentrations than the other retarding evaluated.

Wormholes in carbonate formations can acquire different structures depending on the rate of acid injection. At very low injection rates, there is no wormhole at all, as only the face of the formation dissolves. Wormholes that do form at low injection rates tend to be broad and conical. Close to the optimum injection rate, a dominant, narrow wormhole forms with a small amount of branching. When the injection rate is increased past the optimum injection rate, the acid is forced into less permeable zones and creates a ramified (highly branched) wormhole. Ramified structures will transition to uniformly dissolved rock at very high injection rates. By comparing the characteristics of the injection face of the cores from the acid injection experiment described in evaluations above, estimates of the wormhole characteristics can be made. Table 2 provides the low acid injection rates, break through times and pore volumes, from the evaluations above at 200° F., and FIGS. 4A-4C graphically illustrate the core face images and break through characteristics at low acid injection rates at 200° F. (photographic representations are provided in U.S. Provisional Application Ser. No. 62/154,945, and included herein by incorporation).

TABLE 2 Core face images and break through characteristics at low acid injection rates at 200° F. Fluid => 15% HCl + 15% HCl + 15% HCl 18.5% urea 19% MgCl₂ Injection rate (ml/min) 0.2 0.3 0.2  Break through time (h:mm) >3:30 >1:30 0:34 Pore volumes to break through >3.4  >3 0.53

In the tests performed at 200° F., the core faces treated with 15% HCl (FIG. 4A) and 15% HCl with urea (FIG. 4B), both showed a large amount of core facial dissolution 402 and developing conical wormholes 404. In both cases, however, the confining pressure punctured the sleeve holding the core because too much of the rock face dissolved. For the 15% HCl with MgCl₂ fluid (FIG. 4C), the entry wormhole was much smaller and the wormholes 406 broke through to the opposite face in a timely fashion, 34 minutes with 0.53 pore volumes to break through. These indicate that at lower injection rates, retarded acid with MgCl₂ was effective. Table 3 provides the results of the same experiment conducted at 250° F., with similar comparative results both in data and facial dissolution as shown in FIG. 4D (for HCl alone) and FIG. 4E (for HCl with MgCl₂). A large amount of core facial dissolution 402 and a developing conical wormholes 404 occurred with HCl alone, while little facial dissolution and a narrower wormhole 406 resulted with the HCl and MgCl₂ mixture.

TABLE 3 Core break through characteristics at low acid injection rates at 250° F. Fluid => 15% HCl 15% HCl + 19% MgCl₂ Injection rate (ml/min) 0.4 0.4  Break through time (h:mm) >2:05 0:13 Pore volumes to break through >4 0.34

Example 2

In another example, rotating disk experiments were performed to characterize the relative surface reaction rates of acidic solutions. The experiment was conducted by spinning a marble or limestone disk, at ambient temperature and 1250 rpm, in an acid formulation, and periodically sampling the solution. The samples were then analyzed for the calcium concentration as a function of time, which gives the rate constant of calcite (CaCO₃) dissolution by hydrochloric acid containing solutions. A decrease in rate constant indicates an acid retarding agent formulation whose surface reaction is retarded relative to hydrochloric acid alone, without any retarding agent. The plot in FIG. 5 illustrates slower dissolution rate, or slower rate of Ca²⁺ ions liberation over time, for the 15% HCl solution containing MgCl₂ compared with unmodified 15% HCl within 10 minutes. The results in FIG. 5 are a comparison of 15% HCl alone to 15% HCl mixed with 18.7% MgCl₂ retarding agent.

Example 3

Viscoelastic diverting acids (VDAs) consists of two main components: a viscoelastic surfactant) and hydrochloric acid. The viscosity of VDA significantly increases when the acid starts reacting with the carbonate reservoir (that is, when the pH increases)—this is due at least in part to the molecules of the viscoelastic surfactant rearranging to worm-like micelles and forming a gel structure.

For this example, the fresh VDA included 36 v/v HCl (37 wt % solution), 49 v/v MgCl2 (35 wt % solution), 5% v/v alcohol-containing solvent, 1.6% v/v corrosion inhibitor, and 7.9% v/v viscoelastic surfactant (39 wt % active component). The VES used was erucic amidopropyl dimethyl betaine. The rheology of “fresh” VDA (full HCl capacity) and “spent” VDA (null HCl capacity) are measured at ambient temperature with a Fann 35 viscometer and compared with VDA fluid which doesn't contain MgCl2 salt in the composition. Spent VDA was obtained by fully neutralizing the HCl with a sufficient amount of calcium carbonate powder.

As shown in FIG. 6, the viscosity of the “fresh” VDA containing magnesium chloride was about one order of magnitude lower than the “fresh” VDA which did not have magnesium chloride. Thus, addition of the retarder to VDA reduces friction losses when the fluid is pumped.

As shown in FIG. 7, spent VDA containing magnesium chloride demonstrates higher viscosity than spent VDA without magnesium chloride. Thus, the presence of magnesium chloride could possibly improve diversion properties of VDA.

Mechanistically, it is thought that magnesium chloride and urea can each separately disrupt the hydrogen bond network of water that free protons diffuse through to reach the surface of the porous media of the formation. This slows the diffusion of the acid. Furthermore, it is known that magnesium chloride can lower the dielectric constant of water. Acids tend to have lower dissociation constants in lower dielectric media. The activity of the proton could be lowered in this way by forcing it to associate with its counteranion.

Example 4

Core flooding experiments with modified VDA (as described in Example 3) were conducted using Indiana limestone cores with permeability of 70 mD and porosity of 17%. Each core had a 6″ length and 1″ diameter. The cores were saturated with 2% KCl brine prior to the test. The test temperature was 200° F. VDA is injected at a constant rate into the core until it broke through the other end of the core (PVBT). The injection rate of VDA was varied in range of 0.1-6 ml/min. Dependence of PVBT on acid injection rate is shown in FIG. 8.

As one can see in FIG. 8, the addition of magnesium chloride makes VDA more efficient (less fluid is required to break through the core). In particular, better efficiency of modified VDA is observed at low injection rates (below 6 ml/min). As shown in FIG. 9, the wormhole pattern also changes when the retarding agent (magnesium chloride) is present in VDA. The wormhole gets thinner and less core surface is dissolved with VDA containing magnesium chloride.

Example 5

VDA forms a viscous gel while penetrating the core and reacting with limestone. The viscous gel creates resistance for fluid to flow through the core and the injection pressure builds up. Diversion ability of VDA can be determined as a maximum pressure achieved in core flooding experiments before the fluid breaks through (dP_(max)/dP₀, where dP₀ is brine permeability).

In FIG. 10 one can see the pressure build-up when original VDA and VDA modified with magnesium chloride (as described in Example 3) are pumped through the core. In fact, the addition of magnesium chloride to VDA generates slightly higher pressure to flow through the core at the same injection rate.

Example 6

By fitting the pressure build-up data and PVBT data with new updated correlations, we applied our in-house acidizing simulator for some simple examples to show the benefit of VDA with MgCl₂. The simulator used herein to provide the following simulation results is described in the following reference and patents which are each incorporated herein by reference in their entireties:

P. M. J Tardy, B. Lecerf, Y. Christanti

“An Experimentally Validated Wormhole Model for Self-Diverting and Conventional Acids in Carbonate Rocks Under Radial Flow Conditions”, paper SPE 107854, presented at the European Formation Damage Conference held in Scheveningen, The Netherlands, 30 May-1 Jun. 2007.

P. M. J Tardy

METHOD FOR PREDICTING ACID PLACEMENT IN CARBONATE RESERVOIRS; U.S. Pat. No. 7,603,261, filed in the U.S. Patent Office on Nov. 29, 2006, granted Oct. 13, 2009.

P. M. J. Tardy, B. Lecerf

FLOW OF SELF-DIVERTING ACIDS IN CARBONATE CONTAINING HYDROCARBON RESERVOIRS; U.S. Pat. No. 7,774,183 filed in the U.S. Patent Office on Jul. 11, 2006, granted on Aug. 10, 2010

This example has two layers with different permeability contrasts, varying from 100 md/1 md, 100 md/10 md, 100 md/20 md up to 100 md/50 md. For each of these permeability contrasts, different injection rates are applied, varying from 0.5 bbl/min, 1 bbl/min, 5 bbl/min up to 10 bbl/min. With the same volume of 500 gal VDA or VDA/MgCl₂ pumped into the formation, results of rate per zone and wormhole length are plotted to compare VDA/MgCl2 to original VDA. The data input for the example can be found in Table. 1. The data input to the model also included the composition of the fluids prepared for Examples 3 and 4, and the PVBT data from FIG. 8 and the pressure drop data from FIG. 10 for such fluids was also used in the model.

TABLE 1 Input Data Zone 1 Zone 2 Thickness, ft. 50 50 Perm, md 100 1-50 Porosity 15 15 Zone Pressure, psi 3206 3206

The simulation results are summarized from FIGS. 11 to 42.

From the simulation results, one can conclude that for all the cases run, VDA/MgCl₂ is showing a deeper wormhole penetration than original VDA due to the better retardation factor. In addition, when permeability contrast reduced to 10 or smaller, and rate increased to 1 bbl/min and above, diversion starts to affect the flow rate distribution between the two zones. Based on the simulation results, the VDA/MgCl₂ is showing a better diversion effect, due to the different pressure buildup behavior of these two fluids.

The foregoing description of the embodiments has been provided for purposes of illustration and description. Example embodiments are provided so that this disclosure will be sufficiently thorough, and will convey the scope to those who are skilled in the art. Numerous specific details are set forth such as examples of specific components, devices, and methods, to provide a thorough understanding of embodiments of the disclosure, but are not intended to be exhaustive or to limit the disclosure. It will be appreciated that it is within the scope of the disclosure that individual elements or features of a particular embodiment are generally not limited to that particular embodiment, but, where applicable, are interchangeable and can be used in a selected embodiment, even if not specifically shown or described. The same may also be varied in many ways. Such variations are not to be regarded as a departure from the disclosure, and all such modifications are intended to be included within the scope of the disclosure.

Also, in some example embodiments, well-known processes, well-known device structures, and well-known technologies are not described in detail. Further, it will be readily apparent to those of skill in the art that in the design, manufacture, and operation of apparatus to achieve that described in the disclosure, variations in apparatus design, construction, condition, erosion of components, gaps between components may present, for example.

Although the terms first, second, third, etc. may be used herein to describe various elements, components, regions, layers and/or sections, these elements, components, regions, layers and/or sections should not be limited by these terms. These terms may be only used to distinguish one element, component, region, layer or section from another region, layer or section. Terms such as “first,” “second,” and other numerical terms when used herein do not imply a sequence or order unless clearly indicated by the context. Thus, a first element, component, region, layer or section discussed below could be termed a second element, component, region, layer or section without departing from the teachings of the example embodiments.

Although a few embodiments of the disclosure have been described in detail above, those of ordinary skill in the art will readily appreciate that many modifications are possible without materially departing from the teachings of this disclosure. Accordingly, such modifications are intended to be included within the scope of this disclosure as defined in the claims. 

What is claimed is:
 1. An aqueous composition comprising: water; a viscoelastic surfactant; an acid; and a water-soluble acid retarding agent.
 2. The aqueous composition of claim 1, wherein the acid is selected from the group consisting of hydrochloric acid (HCl), nitric acid, phosphoric acid, sulfuric acid, hydrofluoric acid, hydrobromic acid, perchloric acid, hydrogen iodide, alkanesulfonic acids, arylsulfonic acids, acetic acid, formic acid, alkyl carboxylic acids, acrylic acid, lactic acid, glycolic acid, malonic acid, fumaric acid, citric acid, tartaric acid, or their derivatives, and mixtures thereof.
 3. The aqueous composition of claim 1, wherein the water-soluble acid retarding agent is selected from the group consisting of a salt, urea or one if its derivatives, an alpha-amino acid, a beta-amino acid, a gamma-amino acid, an alcohol with one to five carbons, a surfactant having a structure in accordance with Formula I, and combinations thereof:

in which R₁ is a hydrocarbyl group that may be branched or straight chained, aromatic, aliphatic or olefinic and contains from about 1 to about 26 carbon atoms and may include an amine; R₂ is hydrogen or an alkyl group having from 1 to about 4 carbon atoms; R₃ is a hydrocarbyl group having from 1 to about 5 carbon atoms; and Y is an electron withdrawing group.
 4. The aqueous composition of claim 3, wherein the salt comprises: i) a cation selected from the group consisting of lithium, sodium, potassium, rubidium, cesium, beryllium, magnesium, calcium, strontium, barium, scandium, yttrium, titanium, zirconium, hafnium, vanadium, niobium, tantalum, chromium, molybdenum, tungsten, manganese, technetium, rhenium, iron, ruthenium, osmium, cobalt, rhodium, iridium, nickel, palladium, platinum, copper, silver, gold, zinc, cadmium, mercury, boron, aluminum, gallium, indium, thallium, tin, ammonium, alkylammonium, dialkylammonium, trialkylammonium and tetraalkylammonium, and combinations thereof; and ii) an anion selected from the group consisting of fluoride, chloride, bromide, iodide, sulfate, bisulfate, sulfite, bisulfite nitrate, alkanesulfonates, arylsulfonates, acetate, formate, and combinations thereof.
 5. The aqueous composition of claim 1 wherein the viscoelastic surfactant has a structure in accordance with Formula III:

in which R₁ is a hydrocarbyl group that may be branched or straight chained, aromatic, aliphatic or olefinic and contains from about 17 to about 26 carbon atoms and may include an amine; R₂ is hydrogen or an alkyl group having from 1 to about 4 carbon atoms; R₃ is a hydrocarbyl group having from 1 to about 5 carbon atoms; and Y is an electron withdrawing group.
 6. The aqueous composition of claim 1 wherein the viscoelastic surfactant is erucic amidopropyl dimethyl betaine.
 7. The aqueous composition of claim 1 wherein the aqueous composition is in the form of a gel.
 8. The aqueous composition of claim 7, and having a lower viscosity at a pH below about 0 as compared to a viscosity of an equivalent aqueous composition which does not contain the water-soluble acid retarding agent.
 9. The aqueous composition of claim 1, having a viscosity, at temperatures between about 70° F. to about 200° F. and a pH above about 3, which is higher than the viscosity of an equivalent aqueous composition which does not contain the water-soluble acid retarding agent.
 10. The aqueous composition of claim 9, wherein the water-soluble acid retarding agent comprises the salt.
 11. A method comprising: a) providing an aqueous composition comprising: water; a viscoelastic surfactant; an acid; and a water-soluble acid retarding agent; and b) treating a formation fluidly coupled to a wellbore with an oilfield treatment fluid comprising the aqueous composition.
 12. The method of claim 11, wherein the acid is selected from the group consisting of hydrogen chloride, hydrogen bromide, hydrogen iodide, hydrogen fluoride, sulfuric acid, nitric acid, phosphoric acid, alkanesulfonic acids, arylsulfonic acids, acetic acid, formic acid, alkyl carboxylic acids, acrylic acid, lactic acid, glycolic acid, malonic acid, fumaric acid, citric acid, tartaric acid, and combinations thereof.
 13. The method of claim 11, wherein the water-soluble acid retarding agent is selected from the group consisting of a salt, urea or one if its derivatives, an alpha-amino acid, a beta-amino acid, a gamma-amino acid, an alcohol with one to five carbons, a surfactant having a structure in accordance with Formula I, and combinations thereof:

in which R₁ is a hydrocarbyl group that may be branched or straight chained, aromatic, aliphatic or olefinic and contains from about 1 to about 26 carbon atoms and may include an amine; R₂ is hydrogen or an alkyl group having from 1 to about 4 carbon atoms; R₃ is a hydrocarbyl group having from 1 to about 5 carbon atoms; and Y is an electron withdrawing group.
 14. The method of claim 13, wherein the salt comprises: i) a cation selected from the group consisting of lithium, sodium, potassium, rubidium, cesium, beryllium, magnesium, calcium, strontium, barium, scandium, yttrium, titanium, zirconium, hafnium, vanadium, niobium, tantalum, chromium, molybdenum, tungsten, manganese, technetium, rhenium, iron, ruthenium, osmium, cobalt, rhodium, iridium, nickel, palladium, platinum, copper, silver, gold, zinc, cadmium, mercury, boron, aluminum, gallium, indium, thallium, tin, ammonium, alkylammonium, dialkylammonium, trialkylammonium and tetraalkylammonium, and ii) an anion selected from the group consisting of fluoride, chloride, bromide, iodide, sulfate, bisulfate, sulfite, bisulfite nitrate, alkanesulfonates, arylsulfonates, acetate, formate, and combinations thereof.
 15. The method of claim 11 wherein the viscoelastic surfactant has a structure in accordance with Formula III:

in which R₁ is a hydrocarbyl group that may be branched or straight chained, aromatic, aliphatic or olefinic and contains from about 17 to about 26 carbon atoms and may include an amine; R₂ is hydrogen or an alkyl group having from 1 to about 4 carbon atoms; R₃ is a hydrocarbyl group having from 1 to about 5 carbon atoms; and Y is an electron withdrawing group.
 16. The method of claim 11 wherein the viscoelastic surfactant is erucic amidopropyl dimethyl betaine.
 17. The method of claim 11 wherein the aqueous composition is in the form of a gel.
 18. The method of claim 11, wherein the aqueous composition has a lower viscosity at a pH below about 0 as compared to a viscosity of an equivalent aqueous composition which does not contain the water-soluble acid retarding agent.
 19. The method of claim 11, wherein the aqueous composition has a viscosity, at temperatures between about 70° F. to about 200° F. and a pH above about 3, which is higher than the viscosity of an equivalent aqueous composition which does not contain the water-soluble acid retarding agent.
 20. The method of claim 19, wherein the water-soluble acid retarding agent comprises the salt. 